Microbial processes for increasing fluid mobility in a heavy oil reservoir

ABSTRACT

Methods are provided for increasing overall fluid mobility in a near-wellbore region in an oil sands reservoir, for example in a reservoir having an inter-well region between a first well and a second well of a well pair in which at least a portion of the near-wellbore region is within the inter-well region. The methods may involve inoculating the near-wellbore region with a microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase. Conditions may be maintained in the near-wellbore region so that the microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. ProvisionalPatent Application No. 61/721,452 filed Nov. 1, 2012, which isincorporated herein by reference in its entirety.

FIELD

The invention relates generally to in situ processes for recoveringhydrocarbon from oil sands, and particularly to processes for increasingfluid mobility by inoculating a near-wellbore region in an oil sandreservoir with one or more microorganism.

BACKGROUND

Demand for crude oil in North America has outstripped production levelsfor the last several decades. Conventional oil recovery practices areonly able to recover 50% of the total oil present in even the mostfavourable reservoirs. Conventional recovery levels in less favourablereservoirs, including heavier oil and bitumen reservoirs, can be 10% orless. So-called “enhanced oil recovery” techniques can help access somefraction of total oil or bitumen unavailable by conventional methods.These include: thermal processes, employing, for example, steam, hotwater, solvent, or a combination thereof to heat the reservoir andreduce the viscosity of heavier oil; and non-thermal processes, whichinclude using substances (e.g., solvents, polymers, acids, surfactants)to reduce the viscosity of the oil, increase the viscosity of displacingfluids, reduce interfacial tension between the oil and displacingfluids, and degrade rock formations to allow smoother displacement ofoil.

One example of an enhanced in situ oil recovery technique issteam-assisted gravity drainage (“SAGD”). SAGD is a known thermalapproach to producing bitumen and heavy crude oil from reservoirs. Itinvolves drilling two vertically-displaced (typically about 5 m apart),parallel, horizontal wells into, for example, the lower portion of anoil reservoir. Steam is gradually injected into the reservoir via theupper well (i.e., the injector well). The high temperature of the steamaffords a transfer of heat between the steam and the bitumen or heavycrude oil in the surrounding formation, leading to a decrease inviscosity of the bitumen or heavy crude oil. Gravitational forcesgradually displace oil and bitumen to the lower well (i.e., the producerwell). The producer well collects hydrocarbons, such as oil or bitumen,and any water from the condensation of injected steam, from whence theyare removed to the surface and fractionated. Steam injection can occurcontinuously or discontinuously. As steam rises upward and expandsoutward more oil and bitumen are gradually displaced towards the lowerwell, where production occurs. SAGD improves significantly uponconventional recovery methods: the low steam pressure means thatfracturing between the wells is unlikely to occur; leaking of steam intothe producer well occurs at a low rate; and the overall process isrelatively efficient, resulting in recovery of up to 80% of the totaloil or bitumen in place in some reservoirs. The state of a formation atwhich any fluid such as bitumen, oil, water or gas may travel throughthe region between the two wells (referred to herein as the inter-wellregion or inter-well space), thereby connecting one well to the otherand vice versa, is the state at which “injector-producer communication”is achieved. Typically injector-producer communication (which is alsoreferred to herein as fluid communication or communication) is achievedwhen the inter-well region is heated. In some reservoirs (particularlythose that have little or no underlying aquifer), a long period ofheating is normally required to achieve initial communication(“start-up”) of fluids between the injector and producer. Methods ofshortening the time to inter-well communication (which is also referredto as “accelerating start-up”) have previously been considered,including, for example, by lowering bitumen or oil viscosity (see, fore.g., U.S. Pat. No. 7,934,549).

Methods to enhance oil recovery that incorporate microorganisms havebeen described. In situ methods that employ microorganisms to dislodgeoil from rock formations, or otherwise enhance the recovery of oil fromreservoirs, are known as “microbial-enhanced oil recovery” (“MEOR”)techniques. MEOR methods have many useful applications, including, forexample: producing biopolymers that increase viscosity of waterfloods(see, for e.g., U.S. Pat. No. 4,475,590 to Brown), and producingbiosurfactants (see, for e.g., U.S. Pat. No. 4,522,261 to McInerney etal.).

U.K. Patent No. 2,450,502 to Kotlar describes methods for enhancingheavy oil recovery from a reservoir using a microorganism capable oflowering oil viscosity. Kotlar indicates that microorganisms be injectedduring or after an extraction process. U.S. Pat. No. 8,235,110 to Larteret al. describes general methods of using a preconditioning agent in amobile water film to precondition oil reservoirs.

The following publications describe methods which employ microorganismsfor production or treatment of oil: Canadian Patent Application No.2,638,451; Canadian Patent No. 2,761,048; Canadian Patent No. 2,531,963;Canadian Patent No. 1,317,540; Canadian Patent No. 2,100,328; U.S.Patent Publication No. US/2013/0062053; U.S. Patent Publication No.US/2012/0325457; U.S. Patent Publication No. US/2012/0261117; U.S.Patent Publication No. US/2012/0301940; U.S. Patent Publication No.US/2012/0214713; U.S. Patent Publication No. US/2011/0257052; U.S.Patent Publication No. US/2011/0083843; U.S. Patent Publication No.US/2011/0067856; U.S. Patent Publication No. US/2010/0212888; U.S.Patent Publication No. US/2011/0308790; U.S. Patent Publication No.US/2010/0012331; U.S. Pat. No. 7,922,893; PCT Publication No.WO2011/076925; U.S. Patent Application No. US/2009/0130732. U.S. Pat.No. 5,174,378; Harner et al., J. Ind. Microbiol. Biotechnol. 2011;November: 38(11):1761-1775; PCT Publication No. WO/2011/159924; PCTPublication No. WO/2008/070990; Canadian Patent Application No.2,640,999; Canadian Patent Application No. 2,767,846; Canadian PatentApplication No. 2,823,752; and Canadian Patent Application No.2,823,750.

SUMMARY

In various embodiments, methods are provided which increase overallfluid mobility in a near-wellbore region in an oil sands reservoir. Thenear-wellbore region may for example be within an inter-well regionbetween a first well and a second well of a well pair, or alternativelymay be a single well that is not a component of a well pair.Accordingly, for embodiments where the near-wellbore region is proximalto one or both wells of a well pair, the method may involve increasingoverall fluid mobility in the inter-well region between the first welland the second well of the well pair, for example in connection withstart-up process associated with SAGD production methods.

In one aspect, the method increases overall fluid mobility in anear-wellbore region in an oil sands reservoir. The method involves (a)inoculating the near-wellbore region with one or more microorganism,wherein the near-wellbore region comprises a hydrocarbon phase and anaqueous phase, the viscosity of the hydrocarbon phase being greater thanthe viscosity of the aqueous phase; and (b) maintaining conditions inthe near-wellbore region so that the one or more microorganismmetabolizes at least a portion of the hydrocarbon phase so thatsaturation of the near-wellbore region by the hydrocarbon phasedecreases and saturation of the near-wellbore region by the aqueousphase increases, increasing overall fluid mobility.

In one embodiment, the method increases the overall fluid mobility in aninter-well region between a first well and a second well of a well pairin the oil sands reservoir, wherein the near-wellbore region isassociated with at least one of the first and second well, and at leasta portion of the near-wellbore region is within the inter-well region.For example, the first well may be an injection well, and the secondwell may be a production well. In other embodiments, the methodincreases overall fluid mobility in the region of a single well locatedin the oil sands reservoir which is not a component of a well pair.

In some aspects, inoculating may occur prior to steam-assisted gravitydrainage (SAGD) to pre-condition the oil sands reservoir for SAGD.Optionally, the inoculating may occur after SAGD is completed. Further,the instant process may be used as an alternative to SAGD, and thusinoculating may occurs in lieu of SAGD in an oil sands reservoir fromwhich oil may subsequently be produced. The method may be used inassociation with thermal recovery methods, generally, such as cyclicsteam stimulation (CSS), and/or other recovery methods involving in situdrilling.

Maintaining propagating conditions in at least a portion of theinter-well region may be undertaken so as to ensure viability of themicroorganism within the inter-well region. Such conditions may permitthe microorganism to metabolize at least a portion of the hydrocarbonphase, thereby decreasing saturation of the inter-well region by thehydrocarbon phase and increasing saturation of the inter-well region bythe aqueous phase.

According to another aspect, a cycling process may be employedcomprising: (c) injecting or circulating a heated cycling fluid withinone or both of the first or second well in fluid communication with thenear-wellbore region, to mobilize fluids within the near-wellboreregion; and (d) repeating steps (a) and (b) so that the microorganismmetabolizes a further portion of the hydrocarbon phase. Optionally, thecycling process steps (c) and (d) may be repeated more than once. Thecycling process steps may be repeated for a period of time, such as forabout two weeks or more. The heated cycling fluid may comprise steam orwater, optionally with a solvent, surfactant, or a combination thereof.

The one or more microorganism may be contained in an inoculant solution,and following step (a) the inoculant solution may be absorbed into thenear-wellbore region over a soaking period. Optionally, after thesoaking period, additional inoculant solution can be added into thenear-wellbore region well to increase overall fluid mobility.Optionally, unabsorbed inoculant solution can be withdrawn from thenear-wellbore region after the soaking period; and may be combined withthe additional inoculant solution for adding and re-circulating in thenear-wellbore region. An exemplary total volume of inoculant solution,including that used in step (a) plus the additional inoculant solution,when utilized, may be from about 2× to about 3× the volume of the volumeof inoculant solution used in step (a).

In aspects of the method, the saturation of the near-wellbore region bythe aqueous phase can increase by amounts of 5% or greater, 10% orgreater, for example about 25% or greater. A decrease in the hydrocarbonphase saturation is also observed. As an example, the saturation of thenear-wellbore region by the hydrocarbon phase may decrease by about 50%after a period of about two weeks. In certain reservoirs with highirreducible water saturation, the increase in water saturation observedmay not be as great of a percentage increase, because of the highinitial aqueous phase saturation.

Fluid communication may be established between the first well and thesecond well of a well pair upon completion of step (a) and (b).Subsequently, injecting or circulating a fluid in: (i) the first well;(ii) the second well; or (iii) both the first well and the second wellto establish the fluid communication between the first well and thesecond well may be conducted, using a fluid such as steam or water,optionally including a solvent, a surfactant, or combinations thereof.

Aspects of the method may involve determining a first saturation levelof the aqueous phase in the near-wellbore region prior to inoculating,and determining a second saturation level of the aqueous phase in thenear-wellbore region following inoculating, and optionally determiningthe increase in aqueous phase saturation.

Further aspects of the method may involve determining a first fluidmobility level of in the near-wellbore region prior to inoculating, anddetermining a second fluid mobility level in the near-wellbore regionfollowing inoculating, and optionally determining the increase in fluidmobility.

The one or more microorganism may, for example, be one which canmetabolize hydrocarbons of C16 or greater. The microorganism may be onewhich preferentially metabolizes hydrocarbons of C20 or greater. Theinoculant may comprise microorganisms in the form of a mixture ofbacteria. The mixture may preferentially metabolize heavy ends of theoil in the oil sands reservoir, and may comprise both aerobic andanaerobic bacteria.

Some aspects of the method involve step of injecting heated fluid intothe injection well or circulating heated fluid in the well pair prior tothe step of inoculating. The wells in the well pair each may have asection that extends substantially in a horizontal direction, whereinfluid communication is established between the substantially horizontalsections. The substantially horizontal sections of the wells may besubstantially parallel, and vertically spaced apart.

According to a further aspect, there is provided herein a method ofrecovering hydrocarbon from in an inter-well region in an oil sandsreservoir located between an injection well and a production well. Themethod comprises (a) inoculating the inter-well region with a mixture ofanaerobic and aerobic bacteria that metabolizes hydrocarbons of C16 orgreater; (b) maintaining the viability of at least a portion of themixture of bacteria in the inter-well region so that the mixture ofbacteria metabolizes at least a portion of the hydrocarbon phase havingC16 or greater, to produce a hydrocarbon phase of decreased viscosity;and (c) recovering the hydrocarbon phase of decreased viscosity from theinter-well region. Optionally, steps (a) to (c) may be repeated. In someembodiments, the inoculating of the inter-well region comprisesinjecting the mixture of bacteria into the injection well together witha suitable carrier.

There is described herein a method of increasing overall fluid mobilityof oil in a near-wellbore region in an oil sands reservoir, comprisinginoculating a well with an inoculant solution comprising one or moremicroorganism that metabolizes hydrocarbon of C16 or greater; permittingthe inoculant solution to become absorbed into the near-wellbore regionover a soaking period; and adding additional inoculant solution into thewell to increase overall fluid mobility of oil. Optionally, the methodmay include withdrawing unabsorbed inoculant solution after the soakingperiod; and combining the withdrawn solution with the additionalinoculant solution added into the well to re-circulate in the well.According to an exemplary embodiment, the total volume of inoculantsolution used in the steps of inoculating and adding may be at leastabout 3× the volume used in the step of inoculating. An exemplarysoaking period may be from about 2 to about 3 weeks.

Other aspects and features will become apparent to those ordinarilyskilled in the art upon review of the following description of specificembodiments as detailed in the accompanying figures, and as describedherein.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures illustrate embodiments, by way of example only.

FIG. 1 depicts the geometry of a bottom-water system simulation asdescribed herein.

FIG. 2 depicts wellhead pressure as a function of time for abottom-water simulation (S_(w)=25%) as described herein.

FIG. 3 depicts casing and tubing pressure in the well at 12.5 d(bottom-water geometry, S_(w)=25%) as described herein.

FIG. 4 depicts the geometry of a side-water system simulation asdescribed herein.

FIG. 5 depicts casing and tubing pressure in the well at 12.5 d(side-water geometry, S_(w)=37%) as described herein.

FIG. 6 depicts casing and tubing pressure in the well at 12.5 d(side-water geometry, S_(w)=37%) as described herein.

FIG. 7 depicts maximum tubing well head pressure as a function of watersaturation in a transition zone.

FIG. 8 depicts the geometry of a generic two well SAGD system simulationas described herein.

FIG. 9 depicts the wellhead casing pressure for the two well system as afunction of time.

FIG. 10 depicts casing and tubing pressure in the injector well at theend of 12 d as described herein.

DETAILED DESCRIPTION

Embodiments of in situ processes for recovering hydrocarbon from oilsands are described herein. In particular, processes for increasingfluid mobility by inoculating a near-wellbore region in an oil sandreservoir with one or more microorganism are described. In alternativeembodiments, the processes may for example increase fluid mobility nearboth horizontal and vertical wells, near a single well, and/or betweenwell pairs. Well pairs may include both parallel well pairs and crosswell pairs. The methodology described herein may be used in associationwith and/or in lieu of thermal recovery methods such as steam-assistedgravity drainage (SAGD) or cyclic steam stimulation (CSS), involvingwell pairs or a single well.

In various aspects, the implementation of microbial processes areemployed so as to adjust oil and water saturation levels in a reservoir.Oil saturation is the fraction of the pore space occupied by oil. Mostoil reservoirs also contain some connate water. Oil saturation is rarely100% and usually ranges from 10% to 90% (in what are known as oil/water“transition zones”). Water saturation is the fraction of the pore spaceoccupied by water. Most reservoirs are water wet and contain connatewater. Water saturation may range from 10% to 50% for an oil or gasreservoir and is up to 100% in an aquifer.

One embodiment involves methods of increasing overall fluid mobility inan inter-well region between a first well and a second well of a wellpair in an oil sands reservoir. The reservoir may be characterized ashaving a near-wellbore region associated with at least one of the wells,at least a portion of the near-wellbore region being within theinter-well region.

In selected embodiments, having a well pair wherein the inter-welldistance is X meters, the near-wellbore region can be defined as thevolume of reservoir occupied within a radius of X/2 m from thewellbore(s) in question. For example, for a well pair in which the wellsare 5 m apart, the near-wellbore region may be defined to include up toa 2.5 m radius from each of the two wellbores. In some embodiments, thenear-wellbore region includes the volume defined by a radius of 2-3 mfrom the well, wherein this 2-3 m radius is not necessarily constant(i.e. is variable) along the length of the wellbore. In general, it willbe appreciated that the near-wellbore region contains the wellbore.

Selected methods involve: inoculating the near-wellbore region with amicroorganism, wherein the near-wellbore region comprises a hydrocarbonphase and an aqueous phase, the viscosity of the hydrocarbon phase beinggreater than the viscosity of the aqueous phase. The method furtherinvolves maintaining conditions in the near-wellbore region so that themicroorganism metabolizes at least a portion of the hydrocarbon phase sothat saturation of the near-wellbore region by the hydrocarbon phasedecreases and saturation of the near-wellbore region by the aqueousphase increases.

The near-wellbore region may for example be associated with: (i) aninjector well of the well pair, (ii) a producer well of the well pair,or (iii) both the injector well and the producer well. A singleproduction well may also be associated with the near-wellbore regions,such as utilized in Wedge Well™ technology, which employs a horizontalwell in association with a SAGD operation. The near-wellbore region mayalso be a single well, for example one associated with cyclic steamstimulation (CSS) in which steam is pumped down a vertical well to soakor liquefy the bitumen, which is subsequently pumped to the surfacethrough the same well. The regions nearby either a single well orassociated wells (for example, well pairs) are encompassed as thenear-wellbore region.

Methods may involve maintaining propagating conditions in at least aportion of the near-wellbore and inter-well regions so that themicroorganism propagates within the inter-well region between the firstwell and the second well, the portion of the inter-well regioncomprising a hydrocarbon phase and an aqueous phase, the viscosity ofthe hydrocarbon phase being greater than the viscosity of the aqueousphase.

As used herein, the term “propagating conditions” includes thosefundamental chemical and biological factors which are required formaintaining viability of a microorganism, such as a bacterium, includingthe ability to metabolize hydrocarbons. Without limitation, “propagatingconditions” include the following: an appropriate nitrogen source, anappropriate phosphorous source, and an appropriate carbon source, whichcan include but is not limited to the hydrocarbon in the oil sandsreservoir. Without limitation, “propagating conditions” further includesthe following an appropriate oxygen source; for example, an aerobicbacterium would require an appropriate oxygen source. Withoutlimitation, “propagating conditions” further includes: an appropriatemoisture level, an appropriate pH, and an appropriate temperature. Inthe case of bacterial microorganisms, “propagating conditions” mayfurther include trace metals or salts such as magnesium or sulfur. Theforegoing examples are provided as examples only and are not meant tolimit the foregoing.

The method may further involve maintaining propagating conditions in theinter-well region so that the microorganisms metabolizes at least aportion of the hydrocarbon phase so that saturation of the inter-wellregion by the hydrocarbon phase decreases and saturation of theinter-well region by the aqueous phase increases.

The method may further involve a cycling process involving a subsequentstep of injecting or circulating a heated fluid within one or both ofthe first or second well in fluid communication with the near-wellboreregion, so as to mobilize fluids within the near-wellbore region; andthen, repeating the steps of inoculating the near-wellbore region andmaintaining conditions in the near-wellbore region so that themicroorganism metabolizes a further portion of the hydrocarbon phase.The cycling process may be repeated one or more times. The heatedcycling fluid may be steam. The heated cycling fluid may be water. Theheated cycling fluid may be or may contain a solvent or a surfactant.

The method may be carried out so that saturation of the near-wellboreregion by the aqueous phase increases to about 25% or greater, forexample up to and including about 3 to 5% above the irreducible watersaturation. An exemplary range may be from about 25% to about 37%. Themethod may be carried out so that saturation of the inter-well region bythe aqueous phase increases to about 25% or greater, for example up toand including about 3 to 5% above the irreducible water saturation. Anexemplary range may be from about 25% to about 37%. The method may becarried out so that fluid communication is achieved between the firstand second wells.

The method may further involve injecting a fluid into or circulating afluid in: (i) the first well; (ii) the second well; or (iii) both thefirst well and the second well to achieve fluid communication betweenthe first and second wells. The fluid may be any one or more of thefollowing: steam, water, a solvent, or a surfactant.

The method may further involve determining a first saturation level ofthe aqueous phase in the near-wellbore region prior to inoculating thenear-wellbore region. The method may further involve determining a firstsaturation level of the aqueous phase in the inter-well region prior toinoculating the near-wellbore region. The method may further involvedetermining a second saturation level of the aqueous phase in thenear-wellbore region following inoculation of the near-wellbore region.The method may further involve determining a second saturation level ofthe aqueous phase in the inter-well region following inoculation of thenear-wellbore region. The method may further involve determining a firstmobility level of the aqueous phase in the near-wellbore region prior toinoculating the near-wellbore region. The method may further involvedetermining a first mobility level of the aqueous phase in theinter-well region prior to inoculating the near-wellbore region. Themethod may further involve determining a second mobility level of theaqueous phase in the near-wellbore region following inoculation of thenear-wellbore region. The method may further involve determining asecond mobility level of the aqueous phase in the inter-well regionfollowing inoculation of the near-wellbore region.

The method described herein may further involve a step of injecting aheated fluid into or circulating a heated fluid in the first or secondwell or both prior to the step of inoculating. The wells in the wellpair described herein may each have a section that extends substantiallyin a horizontal direction, the substantially horizontal sections of thewells being oriented in a range from being substantially parallel tosubstantially perpendicular, and wherein fluid communication may beestablished between the substantially horizontal sections. Thesubstantially horizontal sections of the wells may be vertically spacedapart. Alternatively, the wells in the well pair described herein mayeach have a section that extends substantially in a vertical direction,the substantially vertical sections of the wells being substantiallyparallel, and wherein fluid communication may be established between thesubstantially vertical sections. The substantially vertical sections ofthe wells may be horizontally spaced apart. The distance between thesubstantially horizontal or vertical sections of the wells may forexample be about 3 meters. In some embodiments, the first well may forexample be an injection well completed for a steam-assisted gravitydrainage process and the second well may be a production well completedfor a steam-assisted gravity drainage process.

As used herein, the term “light ends” means a fraction of hydrocarbonsfrom oil sands oil having about 20 carbons or fewer, and the term “heavyends” means a fraction of hydrocarbons from oil sands oil having made upof hydrocarbons having about 20 carbons or more.

The method described herein may further involve a step of injecting aheated fluid into or circulating a heated fluid in one or both of thefirst or second well prior to the step of inoculating. The wells in thewell pair described herein may each have a section that extendssubstantially in a horizontal direction, the substantially horizontalsections of the wells being substantially parallel, and wherein fluidcommunication may be established between the substantially horizontalsections. The substantially horizontal sections of the wells may bevertically spaced apart. The distance between the substantiallyhorizontal sections of the wells is about 3 meters, wherein the firstwell may be an injection well completed for a steam-assisted gravitydrainage process and the second well may be a production well completedfor a steam-assisted gravity drainage process.

It would be understood by a person of skill in the art that where fluidmobility is increased between well pairs, as determining the spacing ofthese well pairs is well known in the art. Typically, well pairs may bespaced about 3 to 8 m apart. Alternatively, well pairs may be spacedabout 3-7 m apart, 3-6 m apart, 3-5 m apart, 3-4 m apart, or about 3 mapart.

Similarly, any range of values given herein is intended to specificallyinclude any intermediate value or sub-range within the given range, andall such intermediate values and sub-ranges are individually andspecifically disclosed. For example, inter-well distances in a SAGD wellpair are typically on the order of 5 m, however, this distance may vary,for example over a range of from about 3 to about 8 m, and the recitalherein of a range from 3 to 8 m is accordingly understood to include anyintermediate value or sub-range within 3 to 8 m.

Microorganisms.

The one or more microorganism described herein may be a bacterium ormixture of bacteria. The bacteria may, for example, be a mixture ofanaerobic and aerobic bacteria capable of metabolizing hydrocarbon heavyends of C16 or greater, or of C20 or greater. The mixture may be onethat is similar to or the same as the mixture used in the lab testingphase described herein: BC-10 Bacteria™ (BioConcepts Inc. of Kemah,Tex.) optionally together with a catalyst or activator such as DHC50™,DHC-S50™, DHC-29™, DHA-9™, all available from BioConcepts, Inc. (Kemah,Tex.) which are selected for the ability to metabolize C16 and largerhydrocarbon materials existing in oil. The mixture of bacteria digestthe hydrocarbon, thereby reducing the length of the molecule andproducing by-products which can act as surfactants. This processlightens the heavy ends.

Optionally, one or more other additional strains of bacteria may be usedbe in inoculation step to metabolize the light ends of the hydrocarbonphase (in addition to metabolizing the heavy ends). Specifically, suchadditional strains of bacteria would be ones capable of metabolizing ahydrocarbon fraction having hydrocarbon molecules of 20 carbons orfewer. However, the ability to metabolize heavy ends (or in someembodiments, the preferential use of heavy ends as substrate) carriesthe advantage that the recovered oil becomes lighter and of a higherquality for later use. Typically, microorganisms capable of metabolizinglight ends are used in recovery or remediation following downstreamprocessing, for example in remediation of tailings ponds where heavyends are unlikely to be located. An inoculant microorganism that wouldmetabolize light ends would have the effect of, on balance, increasingthe ratio of heavy to light ends, and may not have the observed effecton API and density.

An exemplary mixture, having 12 strains of anaerobic and anaerobicbacteria have the ability to metabolize carbon chains from about C16 toabout C58. The inoculant bacterial mixture has a life span ofapproximately 6 to 8 weeks. Without being limited to theory, theproducts formed in the bacterial digestion process not only possessreduced reduce hydrocarbon chain length but also may act as surfactantsand solvents, helping to mobilize the oil.

Microbial Products.

The microbial culture will produce smaller/lighter hydrocarbons fromlonger (C20 and greater) heavy ends, thus, resulting in an increasedoverall fluid mobility. Other microbial byproducts may act assurfactants that can advantageously help to mobilize oil adhered to theformation within the near-wellbore region. Further, gases such as H₂ andmethane which may be produced as a result of microbial metabolism ofheavy ends may also contribute to overall fluid mobility by decreasingthe viscosity and density of the oil in the near wellbore region. Anincrease in API, (as a parameter indicative of increased fluid mobility)is an exemplary parameter that can be used to evaluate the outcome ofthe method.

Before, after and in Lieu of Other Thermal Processes.

The inoculation with the bacterial mixture and subsequent increase inoverall fluid mobility may act to precondition a reservoir prior toconducting thermal recovery processes, such as steam-assisted gravitydrainage (SAGD) or cyclic steam stimulation (CSS), so as to acceleratestart-up of a well. Optionally, a well that has completed the economicproduction using a thermal recovery process, such as SAGD or CSS, may befurther exposed to the process described herein, so that inoculationafter the thermal recovery process can result in further production ofresidual hydrocarbon remaining in the near wellbore region, such as theinter-well region when a well pair is utilized in SAGD. By utilizing theinstant process when other thermal processes, such as SAGD or CSS,become less economical (due, in part, to the cost of steam production)recovery from a well after the final cycle of SAGD is completed (or“blowdown”) or after CSS is completed, recovery can be enhanced.

Further, the method described herein can result in such an increase influid mobility (and reduction in viscosity) that the method may beemployed in place of a thermal recovery method such as SAGD or CSS, inwells that would otherwise be suitable for production through a thermalrecovery process. The economics of production may be a parameter used toevaluate the efficiency of using the current method in lieu of otherthermal processes, such as SAGD or CSS. In secondary pay zones which mayhave been conductively heated, but which still may require someadditional fluid mobility to enhance recovery, the method describedherein may be utilized with a secondary pay well to enhance the fluidmobility.

Circulation and Re-Inoculation.

Circulation or re-circulation of an inoculant solution may occur incertain embodiments provided herein. Advantageously, circulation mayallow better colonization of the near-wellbore region, and/or increasedexposure of the one or more microorganism to the available substrate.Once the microorganism has exhausted substrate supply in its immediatevicinity, a circulation of the inoculant solution helps to re-positionmicrobes and encourages colonization in near-wellbore regions that mayhave be inaccessible at the initial inoculation. In order to circulateor re-circulate microorganisms, inoculant solution may be recovered orwithdrawn from a well, such as the first or second well, for example bymeans of a pump. All or any portion of the initial microorganisms may berecovered, and subsequently re-injected into the near-wellbore region.Subsequent cycles of withdrawal/recovery and re-inoculation/insertionmay be undertaken. Fresh inoculant solution and/or new microorganismsmay be included at any stage in the circulation or re-circulation to thenear-wellbore region.

Such circulation and re-circulation steps permit the one or moremicroorganism to mobilize and gain increased exposure to substrate(heavy ends) within the near wellbore region. Optionally, circulationand re-circulation of inoculant solutions may comprise delivery of asubsequent fresh solution of inoculant in place of the solutionwithdrawn, in situations where a change is deemed necessary. Further,the removal, or suctioning out, of original inoculant solution so as tocirculate existing inoculant is also envisioned in certain embodiments,with or without fresh inoculant.

As a further alternative embodiment, additional microorganisms (andfresh inoculant solution) may be inoculated into the near-wellboreregions without withdrawal or removal of the initial inoculant, so as toincrease pressure within the desired region of an oil sands reservoir.Such a re-inoculation step may be a one-time-only occurrence, or mayoccur periodically. In this embodiment, the surface to microorganismcontact may increase by causing enhanced penetration of the nearwellbore region. Inoculant solution may be withdrawn in small amountsand re-injected in the same or greater amounts through a pulsed timing.Such an embodiment can cause mixing of existing colonized microorganismswith fresh inoculant within the near-wellbore region. By pumpingsubsequent inoculant into a near-wellbore region, the previouslyinjected microorganism solution is effectively pressured further intothe oil sands reservoir, so as to further penetrate the region andaccess additional heavy end hydrocarbon substrate.

Pumping or re-inoculation can occur periodically, for example, oncedaily, once every second day, once per week, or by-weekly, as needed.The periodicity with which pumping/pulsing or re-inoculation isundertaken can be determined based on a leveling-off of the observedchange in a fluid mobility parameter, such as viscosity or API, in agiven near-wellbore region. Some reservoirs may benefit from morefrequent periods if the change in fluid mobility occurs rapidly but thensubsequent changes level off quickly.

An exemplary circulation volume of inoculant solution may be about 3× ormore the volume of the standard horizontal section of the well. Thus, asection having a volume of 12 m³ would soak in a total volume pertreatment from 36-40 m³ in such an embodiment.

The recirculation can be adjusted depending on whether the expectedinjectivity is reached or not. For example, it may be that bothproduction and injector wells are inoculated (or either one or other ofthe producer or the injector well). When injecting one well, the firstinjection of 12-20 m³ of inoculant could be permitted a 2-3 week soakingperiod. Optionally, after the initial soaking period, additional fluidmay be pumped into the well so that a total approximately 3-fold (fluidvolume of up to about 36-40 m³) could be injected so as to squeeze thefluid into the near-wellbore regions. Such an option could be conductedby applying higher pressure into the reservoir with N₂ gas in order tomove the injected fluids further in, to permit soaking in. A subsequentsoaking period of 2 to 3 weeks may be utilized. If the expectedinjectivity is not yet reached, the inoculant fluid may optionally bewithdrawn and recirculated.

For situations in which the injector and producer wells are bothinoculated, an exemplary injection of 12 m³ (based on volume of astandard horizontal section of a well) is provided to each well andpermitted a soaking period, for example of 2-3 weeks. Following this,additional fluid may be added to squeeze the fluid and thus themicroorganisms further into the reservoir. Optionally with N₂ gas may beused. The total inoculant volume may be, for example about 40 m³ intotal. Following this addition of fluid, a subsequent soaking period mayensue. Recirculation of the fluid may optionally be undertaken if thedesired injectivity is not reached.

The initial injection and/or subsequent injections may occur byinjecting into both injector and producer wells, or by selecting eitherthe producer well or injector well. Regardless of the strategy selected,an exemplary target volume of about 3× a horizontal well section may beused.

In some embodiments, fluid remaining in a wellbore after the soakingperiod may be removed, for example by aspiration or pumping, and issubsequently then pumping back in to re-circulate, so as to permitbetter movement into and colonization of the wellbore. Further, suchre-circulation may be conducted concomitantly with the addition ofadditional volumes of inoculant, for example to achieve a 3× fluidvolume, which in some instances may be a 36-40 m³ volume of fluid pertreatment. The fluid remaining in the wellbore after the soaking periodcan be either be recirculated or not. The desired or expectedinjectivity can be observed to inform the desirability of this option.

Time Periods.

After an appropriate period of time for the microbe or microbe mixtureto contact and colonize a near-wellbore region, which may for example bean inter-well region, for example a period of about 5 days or more, suchas about 10 days or more, 2 weeks or more, or 3 weeks or more, a highlysaturated hydrocarbon phase will become less viscous, and less saturateddue to the metabolism of the mixed microbial culture.

In an optional embodiment, following an initial soaking period of fromabout 2 to about 3 weeks, an additional volume of inoculant may be addedto the near-wellbore region in order to increase pressure, andeffectively squeeze the inoculant and attendant microorganisms furtherinto the oil sands reservoir. In this way, additional contact is madebetween hydrocarbon substrate and the microorganisms.

Inoculant Composition.

Microorganism may be delivered within microbial culture, together withan appropriate carrier fluid that is water-based. The carrier fluid isone that does not impede microorganism viability, and which contains anappropriate balance of salts and/or nutrients as would be understood bya skilled person. Additional components can be included in the inoculantcomposition. For example, solvents may be added. Components which may bedesirable to include within the well can be included in the inoculantcomposition. For example, downhole activators, downhole catalysts,solvents, surfactants, or buffers may be included in the inoculantcomposition. These components may assist in the delivery andcolonization of the one or more microorganism; may help contribute (evenin a minor way), to an increase in the water saturation (aqueous phaseincrease) of the near wellbore region thereby further facilitating thelater mobility of steam through the formation when SAGD is subsequentlyundertaken, but need not play a specific role in effecting overall fluidmobility. Provided an additive to the inoculant composition does notgreatly impede the overall increase in fluid mobility in a near-wellboreregion, or kill the vast majority of the microorganisms, it may beincluded in the composition.

Exemplary quantities of solvent, when present (such as an organicsolvent), relative to the mixture of microorganisms may be from about 5%to about 60% solvent. For example, from about 10% solvent to 50% solventmay be used. In some embodiments, 20% solvent or 30% solvent may beemployed.

Accelerated Start-Up.

An advantage realized in certain embodiments provided herein is thattime to start-up of a well for production can be reduced, thusaccelerating start-up of a well for later SAGD production. For example,a typical start-up time with steam alone may be 3 months, whileembodiments of the method described herein may accomplish start-up of awell into production in 4 to 6 weeks. Accelerated start-up time isdesirable to more economically extract entrained oil from oil sand inthe near-wellbore region. Steam will impact the viability of themicroorganisms colonized in the near-wellbore region. Thus once SAGDbegins, the impact on fluid mobility attributable to the microorganismsis lessened over time. The conversion of heavy ends to lighter (shorter)hydrocarbons due to metabolism by the microorganisms will have aninitial effect in SAGD, in that fluid mobility of the oil produced willbe enhanced.

Inoculation after SAGD or Other Recovery Process is Completed.

Steam-related oil recovery processes will result in a reduction of most,if not all, of the colonized microorganisms within a near-wellboreregion. However, once the final cycle of a recovery process, such asSAGD cycle or CSS, is completed, a further inoculation could be employedto re-colonize the region and recover residual hydrocarbon.

During the “blowdown” period of SAGD, bitumen production continues withoperations maintained under the same control scheme employed inconventional SAGD operations. Bitumen production rates decline over timeas the growth rate of the steam front slows under gas injection.Production operations may continue until bitumen production declines toan uneconomic rate, at which time approximately 65% of the producibleoil is projected to have been removed. Microbial inoculation accordingto the method described herein can be used at this stage to help withthe mobility of the remaining oil, as thereby considerably decrease oilviscosity to an additional extent (and maximize recovery) at the pointwhen steam and gas injection become uneconomic.

Embodiments in which a near-wellbore region is inoculated after thefinal SAGD cycle with the one or more microorganisms, can serve tomaximize recovery of some of the remaining oil in an oil sandsreservoir, when the use of steam becomes uneconomical. The near-wellboreregion into which an inoculant solution is provided, after conventionalSAGD production, has both a hydrocarbon phase and an aqueous phase,although much of the hydrocarbon has already been removed in SAGD. Theviscosity of the hydrocarbon phase is nevertheless greater than theviscosity of the aqueous phase, and thus the method of increasingoverall fluid mobility, as described herein, can assist in furtherhydrocarbon removal.

In certain SAGD operations, horizontal wells pairs may be drilled withone well disposed above the other. Multiple well pairs may be drilledfrom a single well pad, and over time, a pocket of unrecovered bitumenmay forms in the space between two well pairs. Optionally Wedge Well™technology allows access the wedge of bitumen via a single horizontalwell drilled between two SAGD well pairs and pumping the oil to thesurface through this additional well. The process described herein maybe used before, after, or in lieu of Wedge Well™ technology.

Conditions Under which Microorganisms are Maintained.

Maintaining favorable conditions in the near-wellbore region allows theone or more microorganism to remain viable, and/or to propagate. Theconditions permit the microorganism to survive and colonize in thenear-wellbore region, and to metabolize the heavy ends as an energeticsubstrate. Such conditions may pertain to temperature, the presence ofadditives or solvent in an inoculant solution (or separately added to areservoir), substrate within an inoculant, and other parameters.

Well bore conditions pertaining to start-up in a SAGD operation permitthe one or more microorganism to remain viable in the near-wellboreregion. Non-aqueous solvents may be included in the inoculant solution,or added separately to the near-wellbore regions, in modest amounts thatdo not affect microorganism viability. For example, a hydrocarbonsolvent such as ethane, propane, or butane or larger alkanes (andmixtures of these) may be included. Aromatic solvents, such as xylene,benzene, toluene, phenol, or mixtures of these may be employed, asdescribed in Canadian Patent No. 2,698,898, herein incorporated byreference in its entirety.

Inoculant is added under conditions that are sub-fracturing conditions(pressure or injection rate or both), and at an ambient temperature thatpermits survival of the microorganisms. Under colder seasonal climateconditions, care can be taken to ensure that the microorganism inoculantsolution is not frozen, but is maintained for injection at a temperaturethat reasonably permits viability to be maintained. No heating isrequired for inoculation of the near-wellbore region, provided theinoculant is protected from excessively cold ambient climatetemperatures prior to inoculating.

Gas may be included in the conditions of the near-wellbore region, suchas air, oxygen, and nitrogen, provided the gas does not exclude thelevel of oxygen necessary for survival of aerobic bacteria.

The conditions may be designed to permit the inoculated microorganism tosoak into the near-wellbore region for a period of time so as todisplace, colonize, and interact with (metabolize) substrate within thenear-wellbore region. A typical candidate oil sands reservoir may be onein which the bitumen or heavy oil density is about 15° API or heavier,such as 12°API or heavier. An exemplary gravity of 8-10° API may befound in the oil sands reservoir within which the near-wellbore regionsis located.

SAGD Start-Up and Optional Conditions.

By way of comparison, standard conditions for SAGD (steam) start-up (notinvolving the inoculating and colonization by microorganisms, asdescribed herein) may involve well pairs into which steam is injected inan amount of about 200 ton/day, with an injector bottom-hole pressure(BHP) of about 5 MPa, and a producer BHP of about 4.8 MPa, which is wellbelow a typical fracture pressure. The startup stage of SAGD establishescommunication between injection and production wells. An averagestart-up time for SAGD start-up may be about 90 days, and the amount ofsteam utilized for start-up may be in the range of about 20,000 m³.Initial reservoir conditions typically show negligible fluid mobilitydue to high oil viscosity and lack of water saturated zones in theinter-well region. SAGD start-up using steam can be supplemented,accelerated or replaced with the method described herein in which fluidmobility is increased using microorganism inoculation and colonizationof the inter-well region.

Further optional conditions which may be employed in start-up, eitherbefore or after inoculation are described in Canadian Patent ApplicationNo. 2,757,125, the entirety of which is hereby incorporated byreference. Methods for steam-related oil recovery from an oil sandreservoir are described in this document. As well, the document teachesconditions under which fluid communication may be established between awell pair in an oil-sand reservoir having a dilatable inter-well region.Steam or water may be circulated within one or both wells of a wellpair, to apply sufficient pressure to dilate the oil sands in theinter-well region. In this way, steam or water dilation may be employedto enhance fluid communication between the well pair. Such a method maybe employed in concert with the method described herein for increasingoverall fluid mobility.

An Embodiment, In Practice

Exemplary procedures which may be used in the field for SAGD wells mayinclude the following details. It is to be understood that the procedureneed not be limited to these exemplary embodiments.

Treatment with one or more microorganism, as described herein, may occurby placing an inoculant solution containing the microorganism intoplaced in one or both of the injector or producer SAGD wells. Varyingdurations of time may be employed to allow for the solution to soak intothe formation and decrease bitumen viscosity. The optimal time requiredfor soaking in may depend on characteristics of the oil sands reservoirin the region.

A mixture of microorganisms may be used, such as the 12 strain mixture,noted above, containing aerobic and anaerobic bacteria that have beenselected to degrade the heavy ends (C16 hydrocarbons or greater) of thebitumen. In some embodiments, although not wishing to be limited bytheory, the microorganisms may produce byproducts that act asbio-surfactants and solvents. Gases may also be produced. The bacteriacan colonize a portion of, or the entire near-wellbore region, whilemetabolizing the heavy ends of hydrocarbon as food source. The bacterialculture can stay viable for is 6-8 weeks. Strains that can last forshorter or longer periods of time may be employed. The microorganismsmay optionally be designed not to reproduce, or to have reducedviability following a set period of, for example 6-8 weeks.

To prepare the wells for the SAGD stage, and achieve communication wherethere is lack of injectivity, the inoculant solution can be pumped intoboth the injector and producer wells, or only into one of the injectoror the producer well. If it is decided to inoculate both injector andproducer wells, an exemplary amount of about 12 m³ of fluid may beincluded in each well. If it is decided to inoculate only one well, aninitial volume 20 m³ can be pumped into the well.

After a soaking period of 2-3 weeks, the microbial solution may berecirculated in order to induce the microorganisms to keep moving andcolonizing along the wellbore. Optionally, additional volumes ofinoculant solution can be injected into the wellbore in order to squeezethe rest of the microorganisms further into the reservoir. Theadditional volume would then be permitted a further soaking of about 2-3more weeks. Estimated total volumes to be injected in this example wouldbe about 36-40 m³, or 2× to 3× the initial volume of inoculant solution.

Wells may be tested for communication utilizing steam injection into theinjector well. If communication is achieved between well pairs, normalSAGD operations may then commence. As microorganisms typically die intemperatures higher than 95° C., the start of SAGD ends the role of theinoculant microorganisms. However, subsequent re-inoculation cycles mayoccur.

In the event that communication is not achieved, an alternative, such asdilation or steam circulation start up methodologies may also beconsidered.

EXAMPLES Example 1 Simulation Single Well Overview of Example 1

Two sets of simulations were performed to illustrate the effect of watersaturation on start-up steam mobility Steam injection was simulatedthrough the producer and no injector was simulated. A homogeneous modelwith live oil (15% wt methane) was used in the simulation. The producercompletion was modelled after a standard SAGD well. A steam injectionrate of 240 t/d was maintained until a cumulative injection volume of3000 t was achieved (12.5 d).

In the first set of simulations, bottom-water was used to provide thereservoir with a mechanism for water displacement. The minimum watersaturation for which a flow rate of 240 t/d could be sustained wasS_(w)=25%. Maximum wellhead pressures for the system at the limitingwater saturation were approximately 5422 kPag in the casing and 6400kPag in the tubing. The tubing pressure at the wellhead corresponds tothe maximum allowable wellhead pressure. Maximum down-hole pressure inboth the tubing and casing were near 6400 kPag suggesting that at asaturation of S_(w)=25% a large pressure gradient must exist in order topush steam from the well, through the transition zone and into thebottom-water. It should be noted that this maximum steam pressure needonly be maintained for a short time (roughly 1 d) until the mobility ofthe water in the reservoir improves.

In the second set of simulations, a water-rich zone at equal elevationto the pay zone was used to provide a mechanism for water displacement.The minimum water saturation for which a flow rate of 240 t/d could besustained was S_(w)=37%. Wellhead pressures for the system (attransition zone S_(w)=37%) reached a maximum of 5500 kPag and 6400 kPagfor the casing and tubing, respectively. Down-hole pressure wasapproximately 4500 kPag in the casing and 4800-4700 kPag in the tubing.

In both simulations, the minimum water saturation was the saturation atwhich the wellhead pressure reached the constraint of 6400 kPag (or 6500kPag absolute). The higher minimum water saturation for the second setof simulations (with mobile water located at equal elevation to thereservoir) is due to the shorter and wider transition zone.

Details of Experimental Example 1

An objective of this Example was to determine the lowest possible watersaturation which allows for steam injectivity of 240 t/d per well pairand a cumulative steam injection of 3000 t during well start-up. Twogeometries were considered in this Example. The first consisted of ahomogeneous live-oil reservoir with bottom-water. The second consistedof an identical reservoir, but with the bottom-water replaced by aninfinitely large water-rich region at the same depth as the pay zone.

In both simulations, the reservoir dynamics as well as the wellboredynamics in the horizontal and build sections were simulated. A summaryof the reservoir properties and conditions is listed in Table 1 below.The wellbore was modelled using a standard completion approach to SAGDin an oil sands reservoir.

TABLE 1 Reservoir Properties Property Value Units Initial Temperature 12° C. Initial Pressure 3000 kPa Methane in Oil 15 Mol % Ka (x/y/z) 4/4/2Darcies Initial Oil Saturation 80 % Initial Water Saturation 20 %Porosity 0.35 Width/Length/Height 50/732/20 m

Simulation details are as follows: casing, tubing and ports were allincluded in the simulation. The Bubble tube was not included in thesimulation as it has minimal effect of the flow dynamics. The port wassimulated using a compressible port model. Heat loss around thereservoir and build section was simulated using a shale property model.It should be noted that half-geometry models were used for thereservoir. As a result, the simulation stopped when (3000/2=) 1500 twere injected. Also, the in-simulation rate of injection was half of the240 t/d specified for this problem.

The infinitely-large water region was simulated using a water-richregion (S_(w)=100%) containing several production sources. The pressureof these production sources was kept at 3000 kPa. This allowed mobilefluids at pressures greater than 3000 kPa to be removed from the system.

Two geometries were considered in Example 1. A geometry for the bottomwater simulations and a geometry for the side-water simulations.

Bottom-Water Simulations.

The first set of simulations was proposed for the geometry illustratedin FIG. 1 herein. Under this geometry, a homogeneous rectangularreservoir of live oil was bounded on three sides by a shale heat-lossgrid and underneath by bottom-water (S_(w)=100%). In addition the bottom2 m of the reservoir contained a transition zone with 50%>S_(w)>20%. Theproducer well (which was operated as a steam injection well) was placedin the middle of the transition zone (i.e., 1 m above the bottom-water).

The simulations were run until a cumulative injection mass of 3000 t(1500 t in-simulation due to half-geometry) was achieved. The injectionrate was 240 t/d (120 t/d in-simulation due to half-geometry). At awater saturation of 25% it was found that an injection rate of 240 t/dwas sustainable. However, at a water saturation of 22%, it was foundthat the injection rate of 240 t/d was not sustainable. As a result, thepredicted minimum water saturation is between 25% and 22%. A value of25% is reported in this work because it is the lowest value for which arate of 240 t/d was successfully sustained.

In order to inject 3000 t of steam at 240 t/d the simulation had to berun for at least 12.5 d. Wellhead pressure as a function of time for thefirst 12.5 d of simulation is shown in FIG. 1. As shown in FIG. 2, themaximum injection pressure was attained early in the simulation (afterroughly 1 d). As the simulation progressed, the wellhead pressuredecreased considerably. This is likely due to the effect of steam inimproving the mobility of water in the reservoir. Specifically, it islikely that the increased mobility is due to viscosity reductionassociated with temperature rise due to steam penetration andcondensation in the reservoir.

Casing and tubing pressure for the bottom-water system, after 12.5 d, asa function of distance from surface is shown in FIG. 2 herein. As can beseen from FIG. 3, the pressures in the horizontal section of the wellare in-line with typical operating pressures. This suggests that once ahigh rate of steam injection is obtained it can be maintained.

Side-Water Simulations.

A second set of simulations was proposed for a side-water systemgeometry illustrated in FIG. 4 herein. Under this geometry, ahomogeneous rectangular reservoir of live oil was bounded on four sidesby a shale heat-loss grid and to the side by mobile water (S_(w)=100%).As with the geometry described in the bottom-water section above, thebottom 2 m of the reservoir contained a transition zone with50%>S_(w)>20%. The producer well (which was operated as a steaminjection well) was placed in the middle of the transition zone (i.e., 1m above the bottom-water). The distance of transition zone between theside-water and the producer was 49.5 m.

The simulations were run until a cumulative injection mass of 3000 t(1500 t in-simulation due to half-geometry) was achieved. The injectionrate was 240 t/d (120 t/d in-simulation due to half-geometry). At awater saturation of 37% it was found that an injection rate of 240 t/dwas sustainable. However, at a water saturation of 35%, it was foundthat the injection rate of 240 t/d was not sustainable. As a result, thepredicted minimum water saturation is between 35% and 37%. A value of37% is reported in this work because it is the lowest value for which arate of 240 t/d was successfully sustained.

In order to inject 3000 t of steam at 240 t/d the simulation had to berun for at least 12.5 d. Wellhead pressure as a function of time for thefirst 12.5 d of simulation is shown in FIG. 3 herein. As shown in FIG.5, the pressure dynamics for the side-water system are qualitativelydifferent than the dynamics for the bottom-water system. In theside-water system the wellhead pressure starts low and builds up overtime. While the rate of 240 t/d can be sustained, it is at the price ofever increasing wellhead pressure; as such, it is less likely that thisinjection rate can be maintained past 12.5 d. Unlike the bottom-watersystem, the dynamic whereby steam increases water mobility and allowsfor flow at lower pressures is not present. This may be due to the longpath the injection fluid must take in order to reach the mobile waterand the associated heat.

Casing and tubing pressure, for the side-water system, after 12.5 d, asa function of distance from surface is shown in FIG. 6. As can be seenfrom FIG. 6, the entire horizontal well section is nearly at the maximumwellhead pressure. This suggests that the flow in this system ishindered (and is limited) by the distance and cross-sectional area oftransition zone channel to the mobile water.

From the simulations of the bottom- and side-water systems it appearsthat at the minimum water saturation, the system is constrained by thewellhead pressure. It is useful, therefore to examine the relationshipbetween wellhead pressure and water saturation. To do this, bothgeometries were simulated using S_(w) values of 50, 45 40 and 37%. Thebottom-water system was additionally simulated at S_(w) values of 35,30, and 25%. The maximum tubing wellhead pressure for each simulation asa function of water saturation is shown in FIG. 5 herein.

As can be seen from FIG. 7, the geometry of the bottom-water simulation(characterized by a wider and shorter transition zone) implies that, ata given saturation, less pressure is required to drive a fixed amount ofsteam into the reservoir. The proximity of mobile water is thereforecritical in determining the minimum water saturation at which steam canbe injected into the reservoir.

Conclusions for Example 1

The two foregoing simulations were performed in order to exemplify theeffect of water saturation on the ability of a reservoir to accept steamat a rate of 240 t/d. The first set of simulations corresponded to asystem geometry with bottom-water and a 2 m transition zone with 1 mbetween the well and the bottom-water. For this set of simulations, thesimulation data results reasonably predict that one can inject steam fortransition zone water saturations as low as 25%. This saturationcorresponded to the constraint well head pressure of 6400 kPag. Thesecond set of simulations corresponded to a geometry with side-water anda 2 m (width)×50 m (length) transition zone with the well beingpositioned 49.5 m from the mobile water. For this set of simulations,the simulation data results reasonably predict that steam can beinjected for transition zone water saturations as low as 37%. Thissaturation corresponds to the constraint well head pressure of 6400kPag.

Example 2 Simulation Two Well System Overview of Example 2

A single set of simulations were performed to illustrate the effect ofwater saturation on start-up steam mobility for a generic well pair.Steam injection was simulated from an injector to a producer well. Ahomogenous model with live oil (15% wt methane) was used in thissimulation. The injector and producer completions were modelled after astandard SAGD well pair. The injection wellhead pressure was maintainedat 8000 kPa. A maximum pressure differential of 7000 kPa was maintainedbetween the injector and producer wells.

A water saturation of S_(w)=25% was found to allow steam to be injectedinto the injector at a sustained rate of at least 240 t/d after about 13days. The maximum well head pressure at this water saturation wasapproximately 8000 kPag. It should be noted that the maximum steampressure differential of 7000 kPa need only be maintained for 18 daysuntil the mobility of the fluid in the reservoir improves.

Details of the Experimental Example 2

An objective of this Example was to illustrate that a saturation ofS_(w)=25% was sufficient to allow for a steam injectivity of 240 t/d perwell pair in a relatively short period of time (around about 12 days).

In these well pair simulations, the reservoir dynamics as well as thewell bore dynamics were simulated. A summary of reservoir properties andconditions is provided in Table 1 above. The well bores were modelledusing a standard completion approach in a SAGD well pair.

Simulation details are as follows: casing, tubing and ports were allincluded in the simulation. The Bubble tube was not included in thesimulation as it has minimal effect on the flow dynamics. The port wassimulated using a compressible port model. Heat loss around thereservoir and injector build section was simulated using a shaleproperty model. The simulation was run for 40 days. It should be notedthat this is longer than the time necessary to achieve a rate of 240 t/dof steam injection.

The geometry for the two-well simulations is shown in FIG. 8 herein.Under this geometry, the homogeneous rectangular reservoir of live oilwas bounded on four sides (top, bottom, heel, and toe) by shale heatloss grids. The area to the left and right of the reservoir was notconnected to a heat loss grid in order to allow for half symmetry. Thereservoir was modelled with a 20 m pay thickness and was 732 m inlength. A typical inter-well spacing of 100 m was assumed. The producerwas placed at the bottom of the pay zone. The injector was placed, usinga typical inter-well spacing of 5 m, above the producer.

Tubing (or injection) wellhead pressure was maintained at 8000 kPa forthis simulation. Casing wellhead pressure as a function of time for all40 days of simulation is illustrated in FIG. 9. As shown in FIG. 9,there is little drop in the casing wellhead pressure from 2 to 20 days.As the simulation progressed past about 20 days, the casing wellheadpressure decreased considerably. This is likely due to the increasedmobility of fluids in the reservoir related to steam injection.Specifically, it is likely that the increased mobility is due toviscosity reduction associated with temperature rise related to steampenetration and condensation in the reservoir.

Casing and tubing pressure for the two-well system, after 40 days as afunction of distance along the horizontal section of the well for boththe injector and producer are shown in FIG. 10 herein. As can be seenfrom FIG. 10, the pressure in the horizontal section of the casing is inline with typical operating pressures. This suggests that once a highrate of steam injection is obtained, it can be maintained.

Conclusions for Example 2

The foregoing simulations were performed in order to exemplify theeffect of water saturation on the time taken to establish communicationbetween a well pair. This set of simulations corresponds to a systemgeometry as illustrated in FIG. 7 and having the properties shown inTable 1. For this set of simulations the simulation data reasonablypredicts, that if the initial inter-well water saturation is S_(w)=25%,one can establish inter well communication with a saturated steaminjection rate of 240 t/d at 8000 kPa well head pressure after the endof 12 days.

Example 3 Lab Testing Overview of Example 3

Static tests were conducted in the lab in order to verify theeffectiveness of a bacterial culture in increasing the mobility of fluidin the reservoir. Tests were conducted using a mixture of bacteriacapable of metabolizing heavy ends of C20 or greater from a hydrocarbonphase. In this example mobility parameters of the resulting fluids werestudied in a lab scale reservoir.

Details of the Experimental Example 3

Two tests were conducted in the lab in order to verify the effectivenessof a mixed bacterial culture in upon the mobility of fluids in alaboratory reservoir.

Two samples of 200 g reservoir sand that was highly saturated with oilwere used and completed with 700 ml of a bacterial solution at differentconcentrations in two different containers. This solution contained anaqueous bacterial mixture (70%) and organic solvents (30%). Thebacterial mixture contained a microbial mixture of BC-10 Bacteria™(BioConcepts, Inc., Kemah, Tex.), a mixture of 12 strains of anaerobicand aerobic bacteria, having the ability to metabolize heavy ends, orhydrocarbons of C16 or greater.

In a separate test, a sample with 400 g of reservoir sand and 400 ml ofbacterial solution having the same composition as above, was tested inorder to evaluate the sand/microbial solution relationship to estimatethe volume of solution that will be required to inoculate the well.

The tests were conducted at room temperature. Wells were inoculated withthe bacterial mixture, and maintained at room temperature underconditions adequate for viability and propagation of the bacteria. After24 to 48 hours of exposure, the oil started to separate and mobilizefrom the sand, and sit on top of the samples. After a two week soakingperiod, most of the oil in the sand became mobilized.

The total oil recovered from the samples was measured. For this test,the total oil recovered was quantified and compared to the originalvolume of oil in the original sand.

Table 2 shows the initial sample properties and properties of the oilobserved in one of the 200 g test samples. The designation of crude oilsbased on density may be evaluated with API (American PetroleumInstitute) gravity, a common measure of the density of liquid petroleum,measured in degrees.

TABLE 2 Sample Properties and Initial Oil Properties Property ValueUnits Temperature 18 (room conditions) ° C. Initial Oil Content 90 %Initial Water Content 10 % Porosity 0.35 % API 8-10 Degrees Viscosity122,333 cP Density 1.0076 g/cc Oil volume in sample 27.19 ml Samplevolume 200 g Microbial solution volume 700 ml

Results for Example 3

After two weeks of a soaking period, the 200 g samples were analyzed inthe lab in order to measure the recovered oil new properties andevaluate its effectiveness. It was observed that most of the oilmobilized to the top of the sample. The amount of oil recovered wasquantified and the sand was tested using Dean-Stark method to measurethe remaining oil fraction in the sample. Results were then compared tothe original volume of oil in the original sand in order to evaluate theproperties of the recovered oil and evaluate effectiveness.

The 400 g samples were analyzed after a 23 day soaking period. Oil alsomobilized on top of the jars, and the properties of the recovered wereevaluated following the methodology noted above for comparison with theoriginal properties and volume of oil in the original sample.

The properties of the sample following lab scale microbial treatment ofthe 200 g samples show that, at room temperature (18° C.), initial oilcontent was 90%, while initial water content was 10%. Porosity was0.35%. After microbial treatment API was about 27 degrees, viscosity wasgreatly reduced to about 1.7-1.9 cP, and density showed a change to thelevel of from about 0.887-0.890 g/cc. 14 g of total oil was recoveredfrom one of the samples after 2 weeks of soaking. Additional data isshown in the tables below.

The results confirm that the microbial treatment using a mixture ofbacteria capable of metabolizing heavy ends, resulted in a markeddecrease in viscosity relative to the starting value of the solution.This dramatically impacted the mobility of the oil, increasing API from8-10 to 27, and decreasing viscosity from about 122,300 cP to about1.7-1.9 cP.

Notably, the two week laboratory scale process using the 200 g jars with700 ml of bacterial solution, the total recovered oil was 44-49% of theoriginal sample. This was a satisfactory result. As this was a statictest, it is noted that the remaining oil in the sand could be mobile inthe sand pores. The viscosity of the oil decreased from about 122,333 cPto about 1.7-1.9 cP, and the quality of the oil increased from 8-10 APIto 27 API under room temperature conditions.

In the tests employing the 400 g sample mixed with 400 ml of microbialsolution, the total recovered oil was about 21-40%. This testincorporates the assumption that there is mobile oil in the sand pores.The viscosity of the oil decreased from about 122,333 cP to about 5.4cP, and the quality increased from 8-10 API to 21.8 API under roomtemperature conditions.

A comparison of the parameters indicative of or pertaining to overallfluid mobility before and after treatment of oil sand for the 200 gsamples illustrates good efficacy. The oil content was reduced while thewater content of the sample increased from about 10% to about 12%.Increased water saturation increases the mobility of fluid in thevicinity. Viscosity was greatly reduced from 122,333 to 1.7 cPs in oneof the samples. The density change was also remarkable, starting atabout 1002 g/cc in the original sample, and resulting in 0.877 g/ccfollowing a 2 week microbial treatment. The API also increased fromabout 8-10 to about 27, indicative of a lightening of the oil, and anincrease in fluid mobility attributable to a reduction in heavy endsfollowing microorganism metabolism. Of the 27.19 mL of oil in one of thesamples, about 14 mL of this was recovered. Further data is provided inthe tables below.

Table 3 and Table 4 provide data pertaining to sample characteristicsfor both the 200 g samples and the 400 g samples as well as a control(uninoculated) sample.

TABLE 3 Density and Viscosity of Isolated Oil Fraction Density DensityBacteria:Sample Volume (15° C.) API Sample (g:mL) (mL) kg/m³ (15.6° C.)DPS Pre-treated 200:700 220 890.5 27.3 200 Solution A DPS Pre-treated200:700 240 887 27.9 200 Solution B 200 Control 201:0  n/a n/a n/a 400Control 404:0  n/a n/a n/a 400 Treatment A 400:400 120 924.4 21.5 400Treatment B 400:400 120 922.5 21.8 Kinematic Viscosity Bacteria:Sample20° C. 30° C. 40° C. Sample (g:mL) (cSt) (cSt) (cSt) DPS Pre-treated200:700 2.163 1.827 1.574 200 Solution A DPS Pre-treated 200:700 1.9441.651 1.425 200 Solution B 200 Control 201:0  n/a n/a n/a 400 Control404:0  n/a n/a n/a 400 Treatment A 400:400 9.665 7.272 5.666 400Treatment B 400:400 8.622 6.55 5.144 Dynamic Viscosity Bacteria:Sample20° C. 30° C. 40° C. Sample (g:mL) (cP) (cP) (cP) DPS Pre-treated200:700 1.919 1.607 1.372 200 Solution A DPS Pre-treated 200:700 1.7171.445 1.237 200 Solution B 200 Control 201:0  n/a n/a n/a 400 Control404:0  n/a n/a n/a 400 Treatment A 400:400 8.899 6.644 5.135 400Treatment B 400:400 7.923 5.97 4.651

TABLE 4 Composition of Isolated Sand Fraction Mass Bacteria:SampleSample Mass Dean-Stark Dean-Stark Sample (g:mL) Tested (g) Solids (g)Water (g) DPS Pre-treated 200:700 159.2 127.6 19.3 200 Solution A DPSPre-treated 200:700 148.6 116.8 18.3 200 Solution B 200 Control 201:0 200.6 170.6 2.6 400 Control 404:0  404.9 339.3 3.8 400 Treatment A400:400 462.2 355.2 72.9 400 Treatment B 400:400 456.8 351 61 Dean-StarkFractions Oil Bacteria:Sample Solids Water (Wt. %) by Sample (g:mL) (Wt.%) (Wt. %) difference DPS Pre-treated 200:700 80.20% 12.10% 7.70% 200Solution A DPS Pre-treated 200:700 78.60% 12.30% 9.10% 200 Solution B200 Control 201:0  85.00% 1.30% 13.70% 400 Control 404:0  83.80% 0.90%15.30% 400 Treatment A 400:400 76.80% 15.80% 7.40% 400 Treatment B400:400 76.80% 13.40% 9.80% Recovery Estimated Oil Bacteria:SampleRemaining in Oil Recovered Sample (g:mL) Sand (mL) (mL) RF % DPSPre-treated 200:700 13.81 13.38 49 200 Solution A DPS Pre-treated200:700 15.22 11.97 44 200 Solution B 200 Control 201:0  27.19 n/a n/a400 Control 404:0  61.33 n/a n/a 400 Treatment A 400:400 36.89 24.45 40400 Treatment B 400:400 48.56 12.77 21

The following tables provide a side-by side comparison of results forthe 200 g sample (Table 5) and the 400 g samples (Table 6). Notably, thetwo weeks laboratory scale process resulted in recovery of about 49% ofthe oil.

TABLE 5 Comparison Table before and After Treatment (200 g sample)Sample After Original Sample Microbial Treatment Property(Pre-treatment) (*2 weeks) Oil 90% (So ~7% *Estimated percentageestimated) of oil in the isolated sand fraction Water 10% (Initial Sw)~12%*Estimated percentage of water in in the isolated sand fraction OilViscosity 122,333 cP 1.7 cP Oil Density 1,0076 g/cc 0.887 g/cc Oil API8-10 27 Total oil recovered 27.19 ml 12-13 ml (44-49% from sampleRecovered from sample oil)

TABLE 6 Side-by Side Comparison Table Before and After Treatment (400 gsamples) Sample After Original Sample Microbial Treatment Property(Pre-treatment) (*2 weeks) Oil 90% (So 9.80% *Estimated percentageestimated) of oil in the isolated sand fraction Water 10% (Initial Sw)13.40%*Estimated percentage of water in in the isolated sand fractionOil Viscosity 122,333 cP 5.9 cP Oil Density 1,0076 g/cc 0.922 g/cc OilAPI 8-10 22 Total oil recovered 61.33 ml 13-24 ml (21-40% from sampleRecovered from sample oil)

Results of both tests establish the favorable impact that inoculationwith microorganisms has on fluid mobility parameters. An exemplary fieldtreatment with a microbial solution may employ a volume of the solutionthat is about 3-fold or more of the estimated volume for a standardhorizontal section of the well. An exemplary estimated volume of 800 mof horizontal well section would be about 12 m³, and thus a volume ofthree times this would be about 36-40 m³.

Positive results from this microbial enhanced start-up illustrate thatthe method described herein for increasing overall fluid mobility in anear-wellbore region in an oil sands reservoir has the potential tooptimize the recovery of oil from a reservoir in the same manner as canbe realized using stream-based or solvent-based processes. Benefits ofsolvent utilization may include reduced emissions intensity, reducedwater handling intensity, and reduced fuel gas consumption intensity(with “intensity” referring to per barrel of oil produced). Further, itis beneficial to have optional technologies to supplement or augmentexisting technologies used field recovery from oil sand, as suchtechnologies can act be accessed when economic, environmental, orclimate conditions render certain options less economical.

Conclusions for Example 3

The method described herein was effective at increasing overall fluidmobility in a laboratory scale version of a near-wellbore region in anoil sands reservoir. Oil phase (hydrocarbon phase) saturation decreased,while water saturation (aqueous phase) increased. Viscosity was greatlyreduced, thereby increasing the flowability of the oil. The increase inAPI demonstrates that the heavy ends of the oil were metabolized,resulting in a lighter gravity. A commensurate change in density wasobserved. The recovery observed for this lab scale example serves toillustrate that this method may offer an alternative to SAGD, or may beused for wells after SAGD is completed, in an effort to recover residualoil when SAGD becomes less economical.

While specific embodiments have been described and illustrated, suchembodiments should be considered illustrative only and not as limitingthe invention as construed in accordance with the accompanying claims.Other features and advantages will be apparent from the followingdescription, drawings and claims.

It will be understood that any singular form is intended to includeplurals herein. For example, the word “a”, “an” or “the” is intended tomean “one or more” or “at least one.” Plural forms may also include asingular form unless the context clearly indicates otherwise.

It will be further understood that the term “comprise”, including anyvariation thereof, is intended to be open-ended and means “include, butnot limited to,” unless otherwise specifically indicated to thecontrary.

When a list of items is given herein with an “or” before the last item,any one of the listed items or any suitable combination of two or moreof the listed items may be selected and used. For any list of possibleelements or features provided in this specification, any sub-listfalling within the given list is also intended.

The above described embodiments are intended to be illustrative only andin no way are to be construed as being limiting. The describedembodiments are susceptible to many modifications of form, arrangementof parts, details and order of operation. All such modification areencompassed within the scope defined by the claims.

All citations are expressly incorporated herein in their entirety byreference.

1. A method of increasing overall fluid mobility in a near-wellbore region in an oil sands reservoir, the method comprising: (a) inoculating the near-wellbore region with one or more microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase; and (b) maintaining conditions in the near-wellbore region so that the one or more microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases, increasing overall fluid mobility.
 2. The method of claim 1, wherein the method increases the overall fluid mobility in an inter-well region between a first well and a second well of a well pair in the oil sands reservoir, wherein the near-wellbore region is associated with at least one of the first and second well, and at least a portion of the near-wellbore region is within the inter-well region.
 3. The method of claim 2, wherein the first well is an injection well and the second well is a production well.
 4. The method of claim 3, wherein inoculating occurs prior to steam-assisted gravity drainage (SAGD) to pre-condition the oil sands reservoir for SAGD.
 5. The method of claim 3, wherein inoculating occurs after steam assisted gravity drainage (SAGD) is completed.
 6. The method of claim 2, wherein inoculating occurs instead of steam assisted gravity drainage (SAGD) in the oil sands reservoir, and wherein the method additionally includes the step of producing oil from the producing well.
 7. The method of claim 2, wherein (b) comprises maintaining propagating conditions in at least a portion of the inter-well region so that the one or more microorganism propagates within the inter-well region.
 8. The method of claim 7, wherein the propagating conditions comprise conditions in which the one or more microorganism metabolizes at least a portion of the hydrocarbon phase, decreasing saturation of the inter-well region by the hydrocarbon phase and increasing saturation of the inter-well region by the aqueous phase.
 9. The method of claim 2, further comprising a cycling process comprising: (c) injecting or circulating a heated cycling fluid within one or both of the first or second well in fluid communication with the near-wellbore region, to mobilize fluids within the near-wellbore region; and (d) repeating steps (a) and (b) so that the one or more microorganism metabolizes a further portion of the hydrocarbon phase.
 10. The method of claim 9, wherein the cycling process steps (c) and (d) are repeated one or more times.
 11. The method of claim 10, wherein the cycling process steps are repeated for a period of about two weeks or greater.
 12. The method of claim 1, wherein the one or more microorganism is contained in an inoculant solution, and: following step (a) the inoculant solution is absorbed into the near-wellbore region over a soaking period, and after the soaking period additional inoculant solution is added into the near-wellbore region well to increase overall fluid mobility.
 13. The method of claim 12 wherein unabsorbed inoculant solution is withdrawn from the near-wellbore region after the soaking period; and is combined with the additional inoculant solution for adding into the near-wellbore region, to re-circulate in the near-wellbore region.
 14. The method of claim 13, wherein the total volume of inoculant solution in step (a) plus the additional inoculant solution is from about 2× to about 3× the volume of the volume of inoculant solution used in step (a).
 15. The method of claim 9, wherein the heated cycling fluid comprises steam, water, a solvent, a surfactant, or a combination thereof.
 16. The method of claim 1, wherein: the saturation of the near-wellbore region by the aqueous phase increases by about 25% or greater; and/or the saturation of the near-wellbore region by the hydrocarbon phase decreases by about 50% after about two weeks.
 17. The method of claim 2, wherein fluid communication is established between the first well and the second well following step (a) and (b).
 18. The method of claim 17, comprising injecting or circulating a fluid in: (i) the first well; (ii) the second well; or (iii) both the first well and the second well to establish the fluid communication between the first well and the second well.
 19. The method of claim 1, further comprising: determining a first saturation level of the aqueous phase in the near-wellbore region prior to inoculating, and determining a second saturation level of the aqueous phase in the near-wellbore region following inoculating, and optionally determining the increase in aqueous phase saturation; and/or determining a first fluid mobility level of in the near-wellbore region prior to inoculating, and determining a second fluid mobility level in the near-wellbore region following inoculating, and optionally determining the increase in fluid mobility.
 20. The method of claim 1, wherein the one or more microorganism metabolizes hydrocarbons of C16 or greater.
 21. The method of claim 1, wherein the one or more microorganism preferentially metabolizes hydrocarbons of C20 or greater.
 22. The method of claim 21, wherein the one or more microorganism comprises bacteria that preferentially metabolizes heavy ends of the oil in the oil sands reservoir.
 23. The method of claim 3, further comprising a step of injecting a heated fluid into the injection well or circulating the heated fluid in the well pair prior to the step of inoculating.
 24. The method of claim 2, wherein the wells in the well pair each have a section that extends substantially in a horizontal direction, and wherein fluid communication is established between the substantially horizontal sections.
 25. The method of claim 24, wherein the substantially horizontal sections of the wells are substantially parallel, and vertically spaced apart.
 26. The method of claim 1, additionally comprising circulating or re-circulating the one or more microorganism within the near-wellbore region to increase exposure of the one or more microorganism to hydrocarbons of C20 or greater.
 27. A method of recovering hydrocarbon from in an inter-well region in an oil sands reservoir located between an injection well and a production well, the method comprising: (a) inoculating the inter-well region with a mixture of anaerobic and aerobic bacteria that metabolizes hydrocarbons of C16 or greater; (b) maintaining viability of at least a portion of the mixture of bacteria in the inter-well region so that the mixture of bacteria metabolizes at least a portion of the hydrocarbon phase having C16 or greater, to produce a hydrocarbon phase of decreased viscosity; and (c) recovering the hydrocarbon phase of decreased viscosity from the inter-well region.
 28. The method of claim 27, additionally comprising repeating steps (a) to (c).
 29. The method of claim 27, wherein inoculating the inter-well region comprises injecting the mixture of bacteria into the injection well together with a suitable carrier.
 30. A method of increasing overall fluid mobility of oil in a near-wellbore region in an oil sands reservoir, comprising: inoculating a well with an inoculant solution comprising one or more microorganism that metabolizes hydrocarbon of C16 or greater; permitting the inoculant solution to become absorbed into the near-wellbore region over a soaking period; and adding additional inoculant solution into the well to increase overall fluid mobility of oil.
 31. The method of claim 30, additionally comprising: withdrawing unabsorbed inoculant solution after the soaking period; and combining the withdrawn solution with the additional inoculant solution added into the well to re-circulate in the well.
 32. The method of claim 30, wherein the total volume of inoculant solution used in the steps of inoculating and adding is at least about 3× the volume used in the step of inoculating.
 33. The method of claim 30, wherein the soaking period is from about 2 to about 3 weeks. 